Mark Latham Commodity Equity Intelligence Service

Monday 3rd October 2016
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    Colombia's Santos, FARC scramble to revive peace after shock vote

    Colombia's government and Marxist FARC guerrillas will scramble on Monday to revive a plan to end their 52-year war after voters rejected the hard-negotiated deal as too lenient on the rebels in a shock result that plunged the nation into uncertainty.

    Putting on a brave face after a major political defeat, President Juan Manuel Santos offered hope to those who backed his four-year peace negotiation with the Revolutionary Armed Forces of Colombia (FARC) in Cuba.

    Latin America's longest conflict has killed 220,000 people.

    "I will not give up, I will keep seeking peace until the last minute of my term," he said moments after losing Sunday's plebiscite to those who want a re-negotiation of the deal or an obliteration of the FARC on the battlefield.

    Santos plans to meet all political parties on Monday and send lead government peace negotiator Humberto de la Calle back to Havana to speak to the FARC leadership.

    Rodrigo Londono, the top FARC commander better known by his nom de guerre Timochenko, also offered reassurance the rebels remain committed to becoming a peaceful political party.

    "The FARC reiterates its disposition to use only words as a weapon to build toward the future," Timochenko said after the result. "Count on us, peace will triumph."

    Santos, 65, who was not obliged by law to hold a plebiscite, had said there was no Plan B for the failure of the peace vote, but now appears ready to consider options.

    Colombians, even those who backed the "No" vote, expressed shock at the outcome and uncertainty about the future.

    "We never thought this could happen," said sociologist and "No" voter Mabel Castano, 37. "Now I just hope the government, the opposition and the FARC come up with something intelligent that includes us all."

    The peace accord reached last month and signed a week ago offered the possibility that rebel fighters would hand in their weapons to the United Nations, confess their crimes and form a political party rooted in their Marxist ideology.


    The FARC, which began as a peasant revolt in 1964, would have been able to compete in the 2018 presidential and legislative elections and have 10 unelected congressional seats guaranteed through 2026.

    That enraged "No" supporters, including powerful former president Alvaro Uribe, who argued the rebels should serve jail terms and never be permitted to enter politics.

    Uribe, a onetime ally who has become Santos' fiercest critic, may now hold the key to any potential re-negotiation.

    While the FARC has refused to serve traditional jail terms, it may see no future in returning to the battlefields and so consider some sort of new deal.

    "In the end, the people have spoken: the Colombian government and the FARC have no choice but to renegotiate," said Peter Schechter, director of the Adrienne Arsht Latin America Center.

    The FARC already softened its stance in the original negotiation, publicly admitting for the first time it trafficked drugs, recruited minors and committed human rights violations, including massacres.

    But voters worried the rebels would fail to turn over assets from drugs and illegal mining, potentially giving them a formidable war chest that could outstrip the coffers of traditional parties.

    Regions still riven by the conflict, including poor areas along the Pacific and Caribbean coasts, voted resoundingly in favor of the deal, but formerly violent interior areas pacified during the Uribe presidency largely backed the "no" camp.

    "How sad. It seems Colombia has forgotten about the cruelty of war, our deaths, our injured, our mutilated, our victims and the suffering we've all lived through with this war," said Adriana Rivera, 43, a philosophy professor standing tearfully at the hotel of the "yes" campaign.

    The vote may delay Santos' plans to move on to other matters including much-needed tax reform and other macroeconomic measures to offset a drop in oil income. It will also dent his hopes for a boom in foreign investment in mining, oil and agriculture in Latin America's fourth-largest economy.
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    Germany says watching Chinese takeover interest closely

    The German government is carefully watching the interest of Chinese businesses in taking over companies in Germany, an Economy Ministry spokeswoman said on Friday.

    The spokeswoman declined to comment on a report in German business daily Handelsblatt that potential buyers of shares in lighting group Osram had been in contact with Siemens , which holds a stake in Osram.

    But she added: "We are carefully watching the overall situation, especially concerning takeovers from China."
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    DTE unveils plans to spend up to $1.5 billion on gas plant construction

    DTE Energy expects to formally notify Michigan regulators in October that it plans to build the first of what could be several natural gas-fired power plants as part of an ambitious strategy by the state's largest electric utility to invest up to $1.5 billion to replace a portion of the coal generation it intends to retire by 2023.

    A full-scale application for a certificate of need for the initial project will be filed with the Michigan Public Service Commission in mid-2017, DTE spokesman Brian Corbett said Friday in an interview.

    The Detroit-based company has indicated for months it will rely on natural gas and renewables to replace the St. Clair, River Rouge and Trenton baseload coal-fired plants that will be shut over the next six years. Now, it is revealing specifics.

    One of the first new gas-fired plants the utility will build is likely to be located on existing DTE property adjacent to the 1,395 MW Belle River coal-fired plant in St. Clair County, Michigan, DTE spokesman Brian Corbett said in a Friday interview.

    In all, DTE plans to install about 1,000 MW of energy next decade, although it remains unclear how many gas plants will be built. "We're talking about at least one new gas plant, probably more," Corbett said.

    The first gas-fired plant is targeted for commercial operation in the 2021-2023 time frame.

    DTE Chairman and CEO Gerry Anderson said in a statement his company is "committed to providing Michigan and our customers with reliable, cleaner sources of energy. These new energy generation investments will significantly reduce greenhouse gases by moving to cleaner technologies. Just as important, it enables us to deliver safe, affordable and reliable energy for DTE's 2.2 million customers."

    DTE and Spectra Energy are co-developers of the proposed 255-mile Nexus natural gas pipeline that would carry 1.5 Bcf/d the Marcellus and Utica shale fields to Michigan and Ontario, Canada.

    In September, the companies received an air permit for the $2 billion project. They next need to secure a final environmental impact statement from the Federal Energy Regulatory Commission. If everything goes as planned, construction could start in late 2017, with completion before 2020.

    DTE has about 12,000 MW of generation, including 6,300 MW coal, 2,700 MW natural gas, 1,100 MW nuclear, 950 MW pumped storage hydro and 930 MW renewables. Until this year, DTE had retired only about 200 MW of older coal generation, but after its June retirement announcement for St. Clair, River Rouge and Trenton, DTE has only two remaining coal plants -- Belle River and 3,000 MW Monroe -- that it has not yet planned to retire.

    If the first gas-fired plant is built at Belle River, it suggests that the coal-fired plant probably will be closed sometime next decade as well, although Corbett would not confirm such a scenario.

    "Right now," the company has said that Belle River and Monroe will operate "beyond 2023," he said.

    Indeed, it appears likely that Monroe, on the western shore of Lake Erie and one of the biggest power plants in the Midwest, may be DTE's only coal-fired plant to continue operating past 2030.

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    Oil and Gas

    Russian oil output jumps 4 pct in September to a new record

    Russian oil output jumped by almost 4 percent in September from the previous month to 11.11 million barrels per day (mbp), a new post-Soviet record-high, as companies ramped up drilling amid improved oil prices, Energy Ministry data showed on Sunday.

    The oil output rose amid the talks between the leading global producers, including Russia, to curb production in order to support oil prices, depressed by oversupply.

    Russian Energy Minister Alexander Novak said on Friday that Russia will find mechanisms and instruments needed to freeze oil production should the country reach an agreement with the Organization of the Petroleum Exporting Countries on limiting

    In tonnes, Russian oil output reached 45.483 million versus 45.309 million in August. Last month, oil output in million barrels per day stood at 10.71.

    The rise was led by world's top listed oil producer, Rosneft, whose output rose by 2.6 percent month-on-month, as well as Gazprom Neft, which showed a 5.2 percent jump
    in production last month.

    The jump in Russian production comes not only thanks to conventional oil deposits but also as Kremlin oil champions Rosneft and Gazprom Neft are increasing output of
    hard-to-extract oil,
    despite Western sanctions on Russian shale projects.

    Analysts from Swiss bank UBS forecast a rise of 2.7 percent next year of Russia's overall oil production.

    "Production growth is to be driven by new projects ramp-up and better production management at conventional brownfields (also supported by tax benefits)," they said last month.

    Russia's oil production peaked at 11.41 million bpd in 1988 when it was still part of the former Soviet Union, according to the International Energy Agency. Russia accounted for 90 percent of Soviet output.

    Natural gas production in Russia was at 51.33 billion cubic metres (bcm) last month, or 1.71 bcm a day, versus 45.29 bcm in August.

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    Much 2017 oil demand growth to bypass refineries: BP

    U.S. shale gas will displace a growing portion of the world's expanding energy demand, cutting into the need for oil products from refineries, BP's head of refining economics said on Friday.

    Natural gas liquids (NGLs) from the U.S. shale boom such as ethane, an alternative to naphtha refined from crude, could feed as much as a third of demand growth in 2017, BP's Richard de Caux told the Platts Refining Summit in Brussels.

    Refined oil products already in storage will further undercut refinery profits, he said.

    "We expect a substantial chunk of the incremental demand growth next year to be met by two sources which don't come from a refinery," de Caux said, citing NGLs and oil products in storage.

    This week, the first U.S. ethane cargo arrived at a chemicals plant in Scotland, and de Caux said the vessel was a harbinger of supply to come that would undercut profit support for refineries running crude oil, whose margins boomed over the past two years of cheap crude and stellar demand growth.

    "That's coming out of oil demand," de Caux said of petrochemicals coming from ethane, rather than from refined naphtha, in petrochemical units.

    BP expects demand growth of 1.2-1.4 million barrels per day (bpd) in 2017, of which 300,000-400,000 bpd could come from natural gas liquids. This is up from around 200,000 bpd from as a larger overall demand growth in recent years, de Caux said.

    Other consumption growth would be fed by inventories of oil products, which in the developed world stood nearly 150 million barrels above the five-year average in 2016, "close to full," de Caux said.

    This is likely to limit refinery margins and runs, putting pressure to close on the continent's refineries, along with aging units in Japan and possibly on the U.S. Atlantic Coast – areas where demand growth is stagnating.

    "The cheap oil prices did not save Europe from further rationalizations," he said.

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    China's total 2016 fuel export quotas rise to 46.075 mln tonnes

    China has set its fourth-quarter fuel export quota for refiners at a total of 3.47 million tonnes, bringing the year's total to 46.075 million tonnes.

    This is more than 80 percent higher than the total volumes of gasoline, diesel, jet kerosene and naphtha China exported in 2015.

    Gasoil makes up the bulk of the fourth quarter export quotas at 1.53 million tonnes, followed by gasoline at 1.04 million tonnes. Naphtha and kerosene make up the remaining 900,000 tonnes for the fourth quarter quota.
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    Colombia's Ecopetrol To Invest $13B Through 2020

    Colombia's state-run oil company Ecopetrol will invest $13 billion over the duration of its 2017-2020 investment plan, the company said on Thursday.

    The plan, which also includes reducing costs to save up to $700 million, is based on oil prices of $50 a barrel and foresees output of 760,000 barrels per day (bpd), Ecopetrol said in a statement to Colombia's financial regulator.

    Were prices to reach between $70 and $80 a barrel, production could climb to 830,000 to 870,000 bpd, the statement said.

    Aside from the $700 million in cost reduction, the company is weighing selling off additional assets worth between $700 million and $1 billion.

    Spending on production and exploration could reach $11.5 billion over the duration of the plan, and may grow if crude prices improve, the statement said.

    The company cut its investment plan this year and has been selling off non-oil related assets in a bid to raise funds and streamline its focus.

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    Trinidad bewails LNG market.

    Meanwhile, our oil production has declined drastically, now at 66,000 barrels per day, the lowest in 60 years! And that's not the end of the story. A 2011 audit estimated our oil reserves at approximately 509 million barrels, consisting of 243 million barrels proven, 110 million probable, and 156 million possible, which could be even lower, since risk has not been factored. On the other hand, Rystad Energy has now estimated global reserves at 2.1 trillion barrels, the United States at 264 billion barrels, now with more reserves than Russia at 256 billion and Saudi Arabia 212 billion, other countries with huge reserves being Canada, Iraq, Venezuela and Kuwait. And we must now add Argentina, with the fourth-largest recoverable shale oil resources in the world, 27 billion barrels, expecting to double production from its massive Vaca Muerta fields by 2018. Our reserves are therefore paltry by comparison and with our production down and prices low, it is extremely irresponsible to think of continuing to finance Trinidad and Tobago with proceeds from oil.

    And also from gas, where the American shale revolution is turning things topsy-turvy. Having entered the LNG market last January, the US is now selling gas to the Middle East, recently to Dubai and Kuwait, having already shipped to Argentina, Chile, Brazil, India and Portugal. And, just last Tuesday, America sent its first shipment to Britain, opening a “virtual pipeline” across the Atlantic, with the UK and Europe having access to cheap and abundant US shale gas. “We're in a time of huge change in LNG shipping routes,” says Ted Michael of Genscape, a market data provider. “The old order is being overturned, and we haven't seen the dust settle yet”; and Frank Harris, of Wood Mackenzie consultancy says “there is an awful lot of LNG sloshing around the world at the moment, with even more to come, putting downward pressure on prices,” Credit Siusse forecasting depressed prices for the foreseeable future.

    So why are we relying on gas? More LNG keeps coming with new projects in Australia and the US, both countries heading to surpass Qatar as the world's largest exporter, “a new train coming on stream every nine weeks,” according to BP chief economist, Spencer Dale. And, as I have pointed out before, with improved technology cutting costs by 40 per cent, LNG production will continue escalating, the US and Canada each having between 100 and 200 years of shale reserves, British Petroleum, in its 2016 Energy Outlook, forecasting US shale growth at four per cent annually from now to 2035, to account for some 20 per cent of global output; BP also predicting China, with the world's largest deposits, will become a major shale oil and gas producer over the next 20 years. Other countries are also now exploring shale, including Poland, Algeria, Colombia, Russia and Mexico, and others from the 41 countries with impressive reserves. Spencer Dale says the “shale revolution is here to stay and by 2035, will be responsible for half the gas supply worldwide”.

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    Environmentalists file first suit against ExxonMobil over oil storage

    Environmentalists have filed the first civil lawsuit against ExxonMobil for allegedly not accounting for climate change in maintaining oil storage facilities in the US.

    The lawsuit has been brought regarding storage along the Mystic River in Massachusetts.

    According to the Washington Examiner, the lawsuit is meant to build on a series of high-profile probes initiated this year by Democratic attorney general in New York and Massachusetts.

    According to the Conservation Law Foundation, the investigation was started after seeing the Democratic AGs take action following previous reports.

    The lawsuit is said to be based on two factors, “climate deciet” and Clean Water Act Violations associated with oil storage facilities in Everett.
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    Gas Angst

    For those who fear the worst for the prospects for gas in Europe, Dusseldorf was not a reassuring place to be these last few days. That’s because the highlights of the tenth annual European Gas Summit organised by Platts (part of S&P Global) in the German city persistently returned to the themes that demand forecasts are always too high, that the industry is behind the curve in responding to public concerns about carbon emissions; and that the much-trumpeted prospective sources of supply, notably LNG from the US and eastern Mediterranean, may simply find no room in the European market.

    This approach was kicked off by the veteran gas trader Wolfgang Peters, who blamed the European Union as much as Russia for damaging the reputation of gas as a speedy and cost-effective way of tackling CO2 emissions. “The European Commission will not acknowledge there has been reputational damage to natural gas,” said Peters, who formerly headed RWE’s supply and trading operation in the Czech Republic. “Gas advocacy should be more assertive," Peters said. “Even without a subsidy, it can make a huge contribution to the reduction of greenhouse gas emissions.”

    Peters – who at RWE championed the original Southern Gas Corridor project, the Nabucco pipeline, to bring gas from the Caspian to Europe – said the new SGC, operated by Socar, BP and others, would struggle to secure much further input in the near future to enable it to operate at anything like its planned eventual capacity of 31-32bn m³/yr to Turkey and 20bn m³/yr to Italy.

    “The elephant has given birth to a mouse,” he said of the $40bn SGC project, which in its first phase is to carry 6bn m³ to Turkey and another 10bn m³/yr towards Italy. Likewise, Cypriot analyst and NGW contributing editor Charles Ellinas doubted that gas from the eastern Mediterranean would reach Europe soon, and wondered whether this was truly appreciated by political leaders in Israel and, especially Cyprus, who hope that their countries will eventually reap rich rewards from gas exports. “The message that the EU is oversupplied and is not interested in eastern Mediterranean gas is not getting there,” said Ellinas.

    Much US gas could stay in the US

    In the supply context, however, the most striking remarks came from Trevor Sikorski of Energy Aspects. US LNG, he said, may stay in the US. Although US companies have the capacity to export, the actual gas may wind up serving as an option for export, rather than as a mainstay of global trade. The rest of the world may not need it, he argued, and if the Russians and Norwegians keep prices low in Europe, there may be relatively little US LNG coming to Europe. Subsequently conference chairman Stuart Elliot, summing up the first day’s discussions, noted that Russia and Norway were on track to achieve record exports in 2016, “which suggests there may be something like a price war.”

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    Thai PTTEP to invest at least $1.7 bln in 2017 to maintain output

    Oct 3 PTT Exploration and Production Pcl, Thailand's largest oil and gas explorer, plans to invest at least $1.7 billion in 2017 to maintain its production at the same level as last year, chief executive said.

    PTTEP, the upstream exploration business of PTT Pcl , aims to produce around 323,000 barrels of oil equivalent per day next year, the same level as last year, Somporn Vongvuthipornchai told reporters.

    Hit by weaker oil prices, PTTEP has focused on cost cutting and expects its cost per unit to fall by more than 10 percent to between $31 to $32 a barrel this year after a decline to $29 to $30 a barrel in the first half, he said.
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    U.S. Drilling Rebound Plows Ahead as Oil Rigs Are Added

    U.S. oil producers put more rigs back to work, marking the highest level of activity since February as crude markets headed for a second monthly gain.

    Rigs targeting crude in the U.S. rose a fifth consecutive week, up 7 to 425, Baker Hughes Inc., said on its website Friday. Explorers have added 109 rigs since the end of May. Natural gas rigs rose by 4 to 96 this week, bringing the total for oil and gas up by 11 to 522. Three of the four biggest oil fields expanded this week.

    West Texas Intermediate for November delivery rose 26 cents, or 0.5 percent, to $48.09 a barrel at 1:43 p.m. on the New York Mercantile Exchange. Prices are up 8.1 percent this week and down 0.5 percent this quarter.

    "The push up in prices close to $50 is triggering a response in the rig count. Not sure if we’re seeing a significant enough increase, but if we continue to add rigs, then production levels would rise, which would have a softening effect on prices," Gene McGillian, an analyst at TFS Energy Futures, said by phone. "We have a long way to go until then. The rig count still remains at lower levels than before."

    Regional Gains

    West Texas’ Permian Basin added 3 rigs for a total of 204 operating in what has been the busiest drilling region during the market slump. The Williston Basin in North Dakota added 2 rigs to total 30, and D-J/Niobrara in Colorado added 1. The Eagle Ford Shale in South Texas remained unchanged, according to the Baker Hughes data.

    Oil rigs have continued their climb as members of the Organization of Petroleum Exporting Countries agreed this week to cut production for the first time in eight years in an effort to boost global prices.

    If OPEC manages to implement the cut, then it could reinforce the current rebound in drilling, Andrew Cosgrove, an analyst at Bloomberg Intelligence, wrote Sept. 29 in a report. Lower OPEC production would support the case for another 133 rigs being added from now through the end of 2017, he wrote. "Pricing power could come for land drillers in late 2017 or early 2018 if oil remains supported and rig additions continue."

    Oil prices rose this week after OPEC’s informal talks in Algiers, surging the most in more than five months and leading to a second monthly gain. OPEC’s proposal calls for a cut in production to 32.5 million to 33 million barrels a day, but many industry experts are concerned that members won’t be able to cooperate enough to implement the cut.
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    US Exports of petroleum products climb

    Exports of petroleum products climbed significantly last year, driven by increases in shipments of gasoline, propane, and distillate fuels, such as diesel and heating oil, the Energy Department said.

    Petroleum exports climbed nearly 500,000 barrels a day in 2015 from the previous year, the Energy Department said. Exports of distillates, the biggest segment of U.S. petroleum exports, rose 85,000 barrels a day to  about 1.2 million barrels a day, the Energy Department said. The top destination for the fuel was Mexico.

    Gasoline exports averaged about 618,000 barrels a day last year, up by 68,000 a barrels a day from 2015. Mexico, again, was the biggest customer.

    Propane exports climbed by 193,000 barrels a day  to 615,000 barrels a day, much of it headed to Asia. Propane exports to Asia more than doubled to 220,000 barrels a day from 82,000 barrels a day in 2014, the Energy Department said.
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    Mulling options: Petronas may sell out of PNW LNG or put it on ice

    Malaysian giant Petronas is reportedly contemplating a sale of a majority stake in the Pacific NorthWest LNG project that has recently been awarded the clearance by the Canadian Federal government.

    However, with the nod, the government attached 190 legally binding conditions in order to mitigate the environmental impacts of the C$36 billion (US$27.25 billion) project.

    Immediately after receiving the approval, Pacific NorthWest LNG’s president, Adnan Zainal Abidin, noted that moving forwards to the financial investment decision depends on a complete project review to be conducted over the coming months by PNW LNG and its shareholders.

    The low oil prices have hit Petronas’ profits, forcing the company to cut costs as well as jobs, and now the economics of the PNW LNG project is in doubt with dropping LNG prices.

    The company could sell its majority stake in the project, Reuters reports, citing sources close to the matter.

    Gas prices, costs and returns are set to be reviewed before a final decision is made, according to the report. It is also possible for Petronas to suspend the project until gas prices start to recover and Petronas is able to secure favorable long-term contracts.

    The proposed Pacific NorthWest liquefaction facility will comprise an initial development of two LNG trains of approximately 6 million tons per annum each, and a subsequent development of a third train of approximately 6 mtpa.

    Partners in the project are Sinopec, JAPEX, Indian Oil Corporation and PetroleumBRUNEI.
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    Oil Sands Cost Cutting ‘Close to Bone’ as Crude Recovery Stalls

    Canadian oil-sands producers are running out of tricks to buoy their share prices as crude prices keep bumping up against a $50 ceiling.

    After two years of slashing costs to cope with plunging oil prices, shares began rebounding as the market appeared to hit a bottom earlier this year. Now, with the commodity recovery taking longer than expected -- even with this week’s agreement by OPEC to limit supply -- and the pace of reductions slowing, a correction could be in store for oil-sands shares.

    “We’re getting close to the bone” with cost cutting, said Martin Pelletier, a fund manager at TriVest Wealth Counsel in Calgary, in an interview. He pointed to a “huge gap” between companies’ valuations and the price of oil. Without a solid recovery kicking in soon, companies are "going to go lower."

    It’s a lot harder for oil-sands producers to cut costs than it is for their shale-rock drilling brethren. Shale producers can just stop drilling wells, idling rigs and dispensing with all the equipment and labor that goes along with them. Canadian oil-sands companies such as Suncor Energy Inc. and Cenovus Energy Inc., with the massive facilities required to mine and process tar-like bitumen, can’t scale down so easily.

    Shale drillers also deploy new technology more regularly, boosting efficiency with each new well. Oil-sands developments take years to plan and build and cost billions of dollars. With the low commodity prices, new projects have been canceled or delayed, hampering companies’ ability to introduce the latest, cost-saving equipment.

    That’s left oil-sands producers to rely mainly on slashing operating costs such as labor, non-essential maintenance and spending on garbage trucks and road repairs, to cope with low oil prices in the near term, according to consulting firm Wood Mackenzie Ltd. In the future, new projects will take advantage of technology advances to help reduce capital costs, but that’s an unlikely scenario for the next few years, Pelletier said.

    In the meantime, share-price gains are expected to outpace crude in the coming quarters, raising pressure on producers to deliver better profits. The West Texas Intermediate U.S. benchmark oil price is forecast to rise 2.6 percent by the second quarter next year, while the average target price for a Canadian S&P sub-index of Canadian energy companies is expected to gain almost 14 percent, according to analyst estimates compiled by Bloomberg. The price-to-earnings ratio for the 50-member S&P/TSX sub-index has risen to 350 from 98 in the first quarter.

    WTI rose 1.7 percent to $47.83 a barrel Thursday, after surging 5.3 percent Wednesday following the Organization of Petroleum Exporting Countries’ agreement to reduce the collective’s production to as low as 32.5 million barrels a day.

    Producer Cuts

    Oil-sands producer Cenovus will have cut more than C$1 billion in capital, operating and administrative expenses by the end of the year. Since the end of 2014, operating costs have fallen 31 percent at its oil-sands business, helped by laying off almost a third of the company’s work force -- all with the goal of being able to “make money” at $50 a barrel oil, according to Chief Financial Officer Ivor Ruste in a Sept. 7 presentation in New York.

    “The question, is are these permanent reductions? Or are they cutting down to the bare bones to just withstand the downturn?” said Stephen Kallir, a research analyst at Wood Mackenzie in Calgary.

    Cenovus isn’t finished yet, said spokesman Brett Harris. “We believe we can continue to reduce our overall cost structures,” he said.

    Magnifying Glass

    By lowering operating expenses, the impact goes “right to the bottom line,” boosting margins for existing operations, said Kevin Birn, director at industry consultants IHS Cera’s energy group in Calgary. “So you’re going through everything and scrutinizing everything you need,” he said.

    Companies are also pushing for higher production in a bid to lower per-barrel costs, he said. “We’ve seen more barrels coming from existing facilities than historically they’ve been able to achieve.”

    The average cost to produce a barrel of oil, called the lifting cost, for the five largest oil-sands producers has fallen 35 percent since the beginning of 2015, according to data compiled by Bloomberg. At the same time, net debt to earnings before interest, tax, depreciation and amortization has surged three times as profit fell.

    Larger competitors Imperial Oil Ltd., Canadian Natural Resources Ltd. and Suncor, also have taken billions of dollars out of their operations.

    Cold Lake

    Imperial Oil, Exxon Mobil Corp.’s Canadian affiliate, has reduced unit costs by 35 percent since 2014 at the company’s production operations. At its Cold Lake site, costs have fallen 40 percent, helped by lower prices for natural gas and more use of equipment automation, said Bart Cahir, senior vice president of upstream operations.

    Overall costs to produce a barrel of oil are now below C$20 “but we know we have much more work to do,” Cahir said during a Sept. 21 presentation.

    Suncor has managed to lower oil-sands operating costs in the third quarter to “well below” C$24 a barrel, Chief Executive Officer Steve Williams said in a Sept. 7 presentation to analysts in New York. “Our cash operating costs are in a business which in some cases can last for 50 years.”

    Canadian Natural is “confident that there are ongoing opportunities for further cost reductions,” the company said in an e-mail response to questions about whether more cost cuts are possible, without quantifying reductions.

    Eventually companies will have to invest in new projects and introduce new, more efficient technology to really capture cost savings, said IHS’s Birn. “You can push operating costs down so far, but you will hit a limit.”

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    Utica Condensate Begins Flowing Through Cornerstone Pipeline

    In December 2013 MDN first reported a new $250 million pipeline on the way in the Utica Shale from Marathon Petroleum Corporation, the largest refiner in the Utica Shale region.

    The Cornerstone pipeline will stretch nearly 50 miles from the MarkWest cryogenic processing plant in Cadiz, OH northwest connecting to M3’s fractionator plant in Scio and M3’s cryogenic processing plant in Leesville along the way as it terminates and connects to Marathon’s refinery in Canton, OH.

    The pipeline will carry, at various times, crude oil, condensate and natural gasoline. From Canton, Marathon plans to move condensate and NGLs to Midwest refining centers and into Canada.

    In July the company said Cornerstone would be online by the end of this year (seeMPLX Cornerstone NGL Pipe Done by End 2016, New Projects Coming). Yesterday the pipeline went online–at least part of it did–when Cornerstone flowed condensate from Cadiz and East Sparta…
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    FERC Tells Ohio Valley Connector Project to Open the Valves

    The Ohio Valley Connector (OVC) project is a proposed natural gas pipeline system approximately 37 miles long running from northwestern West Virginia into southeastern Ohio.

    Equitrans, a subsidiary of EQT Midstream which is itself a subsidiary of EQT the driller, is building the pipeline. We reported in July 2014 that the project was green lighted.

    At that time, EQT CEO David Porges said the pipeline will interconnect with both the Rockies Express Pipeline and the Texas Eastern Pipeline and will provide about 1 billion cubic feet (Bcf) per day of capacity.

    In July 2015 we ran a story disclosing that the main customer for the new pipeline is one of EQT’s biggest competitors, Range Resources. Fast forward to today. The pipeline’s project cost has gone up, to $415 million. But the really good news is that the pipeline is now built, and the Federal Energy Regulatory Commission (FERC) has just given EQT permission to turn it on…
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    Alternative Energy

    Tesla posts 70 percent rise in quarterly deliveries, backs 2016 target

    Tesla Motors Inc said on Sunday its third-quarter deliveries rose 70 percent to 24,500 cars, following production improvements, cheaper lease deals and reports of discounts on some vehicles.

    Deliveries are a key metric of performance for the luxury electric vehicle manufacturer, which had missed these targets in the previous two quarters.

    The improved deliveries for the third quarter bring Tesla closer to meeting its second-half 2016 target of 50,000 vehicles, which it reiterated on Sunday. It said in a statement that fourth-quarter deliveries would be "at or slightly above" the third quarter's.

    However, the third-quarter figures included 5,150 vehicles in transit at the end of the second quarter, as Tesla reported in July. Another 5,500 cars in transit would be counted in the fourth quarter, it said.

    Meeting the third-quarter target was a priority for the money-losing Silicon Valley carmaker, which is hoping to raise funds from the equity market later this year for multiple efforts, including building out its factory for the Model 3 mass-market sedan due in late 2017 and the planned acquisition of SolarCity Corp (SCTY.O).

    Tesla experienced production problems earlier this year and began to resolve them in June. It said in July that production would improve from 2,000 cars a week to 2,200 in the third quarter and 2,400 in the fourth.

    Production rose in the third quarter to 25,185 vehicles, implying just shy of 2,000 vehicles per week.

    The company will release third-quarter financial results in early November.

    Chief Financial Officer Jason Wheeler said in August that if second-half production and delivery targets are met, the company had a "great chance of being non-GAAP profitable," without specifying a time period.

    In September, Tesla began advertising its inventory cars, for showrooms or test drives, "at favorable prices and ready for expedited delivery."

    Some analysts expressed concern that discounts, reported extensively on online Tesla forums, would undermine margins.

    Last week, Chief Executive Officer Elon Musk published a memo telling employees to follow the company's policy of not offering discounts on new cars.

    Musk was responding to a research note published on Tuesday by Pacific Crest Securities analyst Brad Erickson criticizing Tesla for offering discounts on Model S inventory cars, not those built-to-order for specific customers, to boost third-quarter sales.
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    Energy investment boom expected in northern Chile

    Investment in Chile’s energy industry is expected to jump over the next five years to as much as $3 billion, which could add about 2.5% to the country’s potential GDP growth, US-based Trade Commissioner Rodrigo Mladinić said.

    Speaking at a media briefing during MINExpo 2016 this week, Rodrigo Mladinić said that projects, many of them in the renewables sector, are expected to also boost machinery acquisitions and generate close to 3,000 new jobs.

    The projects, many of them in the renewables sector, are expected to boost machinery acquisitions and generate close to 3,000 new jobs.

    The trade officer noted that Chile’s rising energy demand, pushed by a booming mining production and economic growth in the past 10 years, has already triggered triggered the creation of 29 solar farms supplying the central grid, with another 15 planned.

    In the north of the country, which is where most copper operations are located, even more have been built, Mladinić said.

    While prices for copper, Chile’s main export, remain subdued, the officer said there are strong signs in the market that suggest the red metal will begin rising by mid 2018. The timing coincides with what industry players such as Antofagasta (LON:ANTO) expect the metal to start swinging back into deficit amid a lack of new projects and as Chinese demand continues to grow.

    There already are encouraging signs, such as this week’s move by Teck Resources, Canada’s largest diversified miner, requesting environmental approval for a revised expansion project at its Quebrada Blanca copper mine in northern Chile.

    Mladinić noted that projects like that one are expected to push demand for engineering services in the mining sector to over $36 billion by 2020.

    A similar figure is estimated for sectors other than mining. Construction work and equipment related to engineering companies may represent a further $29.7 billion. Engineering for closure plans, in turn, may reach $20 million per project, the executive said.
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    Precious Metals

    Argentina judge rules Barrick mine to remain suspended

    A judge in Argentina ruled that Barrick Gold Corp's operations at its Veladero mine would remain suspended, saying repairs were insufficient to reopen it after a leak of processing solution containing cyanide earlier this month.

    Judge Pablo Oritja's decision was based on a report from mining police in San Juan province that found Barrick had not installed security cameras and sensors as required, state news agency Telam said on Friday.

    A spokesman for the province said Oritja had extended the temporary suspension of operations on Thursday until Barrick completes additional work at Veladero, one of its five core mines.

    Barrick President Kelvin Dushnisky told Reuters on Sept. 19 that he thought the mine could start operating again in two weeks.

    Toronto-based Barrick said on Friday that it had completed "critical" work required by authorities for the resumption of operations and was awaiting a final resolution of the matter.

    The world's largest gold producer by output, Barrick does not expect the suspension to cause it to miss its 2016 consolidated production forecast, said spokesman Andy Lloyd.

    Barrick said provincial regulators ordered work in seven areas, including maintenance of the exterior perimeter of the leach pad liner and raising the exterior berm, or bank, over which the processing solution flowed.

    The company gave no estimate of the costs of the work or suspension. It will finalize them once the mine is back in operation, Lloyd said.

    Telam said Oritja would go on vacation on Friday, meaning another judge could handle the case.

    Barrick has not said how much processing solution was spilled. Tests by United Nations investigators in October showed the year-earlier spill had not contaminated local water supplies.

    The company announced the spill on Sept. 15. The province had fined Barrick nearly $10 million for a September 2015 leak.

    Attached Files
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    Base Metals

    Not all 20 mines facing suspension may be halted – Philippine Minister

    The Philippine government may not freeze all 20 mines facing suspension for environmentalinfractions and they will be given time to address any lapses, the Minister in charge of mining said on Friday.

    "Yes if they are able to fix whatever" needs to be fixed,Environment and Natural Resources Secretary Regina Lopez told Reuters when asked if it is possible that not all 20 mines will be suspended.

    "Some of the violations though will take time to fix. So they need to use their employees to fix it."

    Lopez's agency said on Tuesday that 20 more mines have been recommended for suspension and gave them seven days to explain any violations and submit measures to rectify them.

    Manila has already halted 10 mines and suspending another 20 would leave only 11 operating mines in the Southeast Asian country, which accounts for nearly a quarter of the world's mined nickel supply – most of which is shipped to China.
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    Platts assesses Q4 Japan aluminium premiums at $75/mt plus LME, CIF

    Platts assesses Q4 Japan aluminium premiums at $75/mt plus LME, CIF

    Platts on Friday assessed the premium for imported primary aluminium in the fourth quarter of 2016 at $75/mt plus London Metal Exchange cash, CIF main Japanese ports, down 18% from $90-93/mt plus LME cash CIF Japan for Q3.

    The Q4 assessment was on the basis of 10 settlements in total at $75/mt plus LME cash CIF Japan, for seaborne P1020/P1020A ingot for loading over October-December, for a volume higher than 500 mt/month.

    The total volume for the 10 settlements was 9,000 mt/month or more. All of the settlements were also under annual contracts where the total volume is set for the year while premiums were negotiated quarterly.

    Platts specifications are for all quarterly settlements on a CIF main Japanese port basis, negotiated prior to Q4 between two unaffiliated counterparties, for P1020/P1020A 99.7% primary aluminium ingot, with payment in cash against documents, for volumes of 500 mt/month or more.

    Four Q4 settlements were not taken into account for the assessment.

    One deal reported closing at $60/mt plus LME cash CIF Japan was determined to have fallen outside the Platts' specifications, due to a lack of repeatability. The deal was for 1,500 mt/month of Australian, South African, Middle Eastern or other origins universally understood to be Good Western.

    Two deals reported closing at $75/mt plus LME cash CIF Japan were not accounted for, as the parties were affiliated.

    One deal, also at $75/mt plus LME cash CIF Japan, was for less than 500 mt/month.

    Separately, the Q4 premiums for value added products were reported at $74/mt and $75/mt plus LME cash CIF Japan.

    One settlement was at $74/mt plus LME cash CIF Japan, and four at $75/mt plus LME cash CIF Japan.

    Around 20 companies, comprising Japanese trading houses, consumers and overseas suppliers, took part in the negotiations that began in August.
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    Steel, Iron Ore and Coal

    China to allow more coal mines to boost output

    China will allow more coal mines to boost production within 276-330 operating days, after 74 mines were given the green light to increase output, to ensure supply for winter heating and power generation, sources learned from the National Development and Reform Commission (NDRC).

    Besides those identified by China National Coal Association as advanced capacity, coal mines listed as Level I safety mines in 2015 by the State Administration of Coal Mine Safety and those safe and high-efficiency mines recommended by local governments would be allowed to increase output, said official with the NDRC on September 29.

    Moreover, due to such restrictions as coal varieties and distance to end users, some coal-producing provinces could select some mines meeting Level II safety standards in 2015 and include them into the category of accommodation, sources said.

    Newly-built coal mines that would replace outdated ones would also be allowed to commence operation before the old ones are closed, which could be allowed to shut later than previously required, the NDRC said.

    "Such mines (above) would be able to boost production within 276-330 operating days, but other mines must comply with the 276-workday strictly," one source told China Coal Resource.

    The latest move was aimed at securing coal supply for heating, gas supply and power generation purpose the coming winter season and next spring, said the NDRC official.

    This will be carried out temporarily from October 1 till the end of the year, and assessment will be made based on the market situation to decide when to call off it.

    Major coal production bases in China were required to draw up specific schemes, and decide on the mines and their increases of production. The schemes are to be launched before the end of September.

    Given the current market situation, coal firms may adopt flexible working hours during the National Day holidays (October 1-7) to ensure supply, after reporting to relevant local government authorities, the official said.

    Data published by the State Administration of Coal Mine Safety showed that there were 791 coal mines meeting the Level I safety standard in 2015. So, it is expected that more than 900 coal mines could be allowed to produce within 276-330 operating days.
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    More German Coal Plants Face Early Closures as Profits Fade

    German coal-fired power plant closures are poised to accelerate as dwindling margins prompt utilities to retire the stations early.

    A quarter of hard coal-fired generation capacity in Europe’s largest economy may shut ahead of schedule if plant operators forgo spending on upgrades to keep aging stations open, according to Nena AS, an Oslo-based energy consulting firm. Steag GmbH, the nation’s fifth-biggest power producer, is considering shuttering at least five of its 13 German coal stations before plan, Juergen Froehlich, a spokesman for the utility, said by e-mail.

    As German coal plant profitability lingers near its lowest levels in at least five years, other utilities may follow Steag, helping ease a surplus of generating capacity exacerbated by the rise of renewable energy, according to Goldman Sachs Group Inc. While utilities have shut about 18 percent of Germany’s current hard coal-fired capacity since 2011, only 9 percent more is slated to close through 2019, according to consultants Pira Energy.

    “You have a lot of old hard-coal plants in Germany and you need to take investment decisions now if you want to continue operating them,” Bengt Longva, a senior analyst at Nena, said by phone.

    Dark Spread

    The clean-dark spread, a measure of coal-plant profitability, for next month in Germany dropped 57 percent in the past 12 months to EU2.80 per megawatt hour, a third of the five-year average for this time of year, according to broker data compiled by Bloomberg. At the same time, gas-fired generation margins have recovered to 2.86 euros per megawatt hour from minus 8 euros.

    “We have seen some resilience for coal, but dark spreads have been narrowing and along the curve I don’t see how these units will be running next year,” said Bruno Brunetti, a director of electricity at Pira in New York. “Recovery of costs is now becoming a real issue.”

    While fuel prices have risen this year, coal has climbed faster than natural gas. This spurred a 15 percent jump in German gas-fired generation as of July, compared with a decline of 16 percent in hard-coal plant output, according to German utility lobby BDEW. Hard coal makes up about 18 percent of the country’s generation.

    Even with German power prices slumping the lowest in more than a decade, total installed generation capacity has increased by more than 50 percent to 195 gigawatts since 2006 due to the surge in renewables, according to the Fraunhofer ISE research institute. Fossil fuel-plant capacity fell 11 percent in the same period. A gigawatt is enough to power 2 million European homes.

    “The industry is reacting at last,” Goldman Sachs analysts wrote in a Sept. 13 note. More utilities may follow Steag’s move, “further improving the outlook for supply and demand,” they wrote.

    In addition to Steag’s mooted closures of some of its own plants, the utility and RWE AG, Germany’s largest electricity producer, decided to shut their co-owned Voerde A and Voerde B coal units by April next year.

    “What’s happening in Germany is a game of chicken,” said Andreas Gandolfo, an analyst at Bloomberg New Energy Finance in London. “If someone else shuts their power plant first, you benefit.”

    Attached Files
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    India to change rules governing captive coal mines

    India’s Coal Ministry is finalising a new coa lpolicy aimed at liberalising rules governing captive and merchant coal mines against a backdrop of surplus  availability of the dry fuel in the domestic market.

    The new policy is expected to be unveiled within the next month, after the Indian festival holiday season starting next week.

    Among the changes proposed, the most major pertained to captive coal mines, with the new policy said to permit captive coal mining leaseholders making excess production available on the open market as merchant sales, an official in the Coal Ministry has said.

    Explaining the rationale for liberalising the rules, the official said that merchant sale of excess production would ease pressures on mining leaseholders.

    Captive coal mining lease holders are primarily steel producers and thermal power generating companies. Steel companies are reeling under low prices for finished steel and merchant sale from their captive coal mines will assist their cash flow and ease pressures on margins.

    As for thermal power companies, their plant load factor is down to levels of 59%, compared with 70% to 75% about a year ago, owing to falling demand for electricity. This, in turn, has resulted in a sharp reduction in dry fuel requirements and excess production from captive mines.

    However, the government will make it mandatory that allcoal from captive mines made available on a merchant sale basis, is suitably washed or beneficiated at pitheads in line with government’s focus on ‘clean coal energy’.

    Permitting merchant sale of coal from captive mines is also expected to open up a window for leaseholders to leverage the asset and woo fresh investment, the official said.

    For example, steel companies, stressed by outstanding debts, would have the option of hiving off the captive mine into a separate entity and inviting foreign direct investment into thecoal mine asset, the official said.

    However, he was quick to add a caveat that given the depressed international coal business environment and concerns over climate change in developed economies, appetite for investing in coal assets was not too high either.

    A back of envelop calculation indicates that at current average aggregate production from captive coal mines and average consumption of the dry fuel by respective user industries, an estimated 110-million tons of coal could be expected to flow into the open market.

    While the changing the rules governing the production and sale of coal from captive mines is expected to have a salutary impact on leaseholders burdened with excess production, no clarity is available as to how government will tackle the issue of more coal flowing into an oversupplied market.

    At the moment, Coal India Limited is saddled with pithead stocks of 42-million tons and another estimated 20-million tons are stockpiled at thermal power plants.

    Attached Files
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    $1 coal mines turn to jackpots as China’s cuts power rally

    Buying bargain-bin coal mines amid the worst commodity slump in a generation has turned into a savvy bet as prices of the fuel surge.

    Stanmore Coal bought the Isaac Plains metallurgical coalmine in Australia for A$1 in July 2015 from Brazilian minerVale SA and Japan’s Sumitomo when the price of met coal, used to make steel, averaged the lowest in about a decade and just three years after the mine was valued at A$860-million. One year later, spot prices have soared above $200 a metric ton as China’s steel mills crank out record volumes while its mines slow production.

    "It seems like we did get our timing right in this instance," Stanmore CEO Nick Jorss said in a phone interview fromSydney. "When we bought Isaac Plains, hard coking coal was in the $70s. We’ve had pretty substantial movement since then."

    Coking coal has surged almost 170% this year as output fromChina, the world’s biggest miner, tumbles under pressure from the government to cut overcapacity even as demand from steelmakers surges. Prices reached $210.80 a ton as of Thursday, according to The Steel Index.

    Stanmore, which has seen its share price double since the beginning of last month, isn’t the only miner who bought low.Australia’s  TerraCom last week completed the purchase of the Blair Athol thermal coal mine, also for A$1, from Rio Tinto Group as the world’s second-biggest miner exits some of its Australian coal portfolio. Thermal coal in Australia, while unable to match coking coal’s rally, has risen more than 50% this year.

    Miners who struck deals before the recent price surge were well placed to profit from the unexpected revival, even if they’re small producers, said Robin Griffin, research director for global metallurgical coal markets at Wood Mackenzie, a consultant.

    "They were brave enough to make the call to try and make it work," Griffin said. "They wouldn’t have foreseen this spike, but they would have had a more optimistic view perhaps. So, in some respects, you could argue their gut feeling was justified."

    While the $1 headline price appears a bargain, Griffin notes the deals come with costly commitments. Stanmore is responsible for a $32-million obligation for the Isaac Plainsmine, in Queensland state, while TerraCom is also on the hook for costs related to rehabilitating the mine.


    Stanmore is targeting 1.1-million metric tons of coal a year from Isaac Plains, while TerraCom hopes to ship two-million tons annually. Australia, the world’s largest coking coalproducer, exported 186-million tons last year, according to Wood Mackenzie.

    Japan’s Electric Power Development, which owned Blair Athol with Rio Tinto and is known as J-Power, said it decided to sell its stake to a company that was willing to recover the remaining coal resources, according to a J-Power spokesman, who asked not to be named, citing company policy.Sumitomo, Rio Tinto and Vale declined to comment.

    Stanmore’s Jorss expects coking coal contract prices for the fourth quarter to rise above $150 a ton, from the current quarter’s $92.50. Analysts at Macquarie Group forecast deals will be agreed at $170 a ton, which is still far short of the record of $330 a ton in 2011.

    “If they have material to sell, the funds will just roar in this quarter,” Wood Mackenzie’s Griffin said. “If prices continue into the next quarter and into the first quarter of 2017, it will look like a master stroke."

    TerraCom chairperson Cameron McRae, a former Rio Tinto executive, said there were good bargains to be found in unwanted coal assets.

    "The extent of the commodity down-cycle has put a lot of miners under pressure and you’ve seen companies sell up because their balance sheets require it," McRae said. "When you see a significant down-cycle you will always see assets come onto the market."
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    China's iron ore party rolls on in September, underpinning prices

    China's appetite for imported iron ore continued unabated in September, with vessel-tracking data showing seaborne arrivals should at least match the strength shown in recent months.

    Shipping data compiled by Thomson Reuters Supply Chain and Commodity Forecasts shows that 85.24 million tonnes of the steel-making ingredient arrived at Chinese ports in September.

    This was higher than the 82 million tonnes estimated for August and only slightly below the 85.67 million for July, which was the highest so far this year.

    Vessel-tracking data doesn't exactly tally with official Chinese customs numbers, with the 647.8 million tonnes recorded for the first eight months of 2016 being 3.26 percent below the customs figure of 669.65 million tonnes.

    Preliminary customs data for September is expected to be released next week.

    Much of the difference can be explained by vessel-tracking not capturing iron ore imports that arrive by land, such as the 3.6 million tonnes from Mongolia in the first eight months, or from countries where ascertaining what ships are transporting is challenging, such as North Korea.

    Nonetheless, the September ship data suggests that iron ore imports by China, which buys about two-thirds of global cargoes, remained robust, thereby underpinning the sustainability of this year's rally in prices.

    Spot Asian iron ore <_.IO62-CNISI> ended at $55.20 a tonne on Sept. 30, staying near the middle of the roughly $11 range it has traded in since June.

    Prices are up 28.7 percent so far this year, although iron ore is down from its peak in 2016 of $68.70 reached in April amid what many analysts believed was a hot-money speculative bubble in the Chinese domestic market.

    The fact that iron ore managed to hold the bulk of its gains so far this year, even after the authorities in Beijing took steps to limit speculation on the country's domestic commodity exchanges, suggests that it has found a more secure footing.

    Much of this is built on the fact that China is producing more steel than forecast, with crude steel output gaining 3 percent in August from a year earlier, the sixth straight monthly increase.

    For the first eight months of the year, steel output was 536.3 million tonnes, down a mere 0.1 percent over the same period in 2015, and casting doubts on Beijing's commitment to reduce excess capacity.

    It's unlikely that steel output will decline over the whole of 2016, given that prices remain solid, with benchmark Shanghai rebar up 34 percent in yuan terms so far this year.

    Steel demand is being led by a revived housing sector in China, with ANZ Banking Group saying in a research note on Sept. 29 that it expected this cycle to last 12-18 months, suggesting relatively strong steel demand lasting through 2017.

    If this is the case, it's further likely that demand for imported iron ore will remain robust as well, which suggests that the price gains seen so far in 2016 are sustainable.


    Much will depend on how much new supply is added to the seaborne market, and whether this will be sufficient to exert downward pressure on prices.

    Brazil's Vale, the world's biggest iron ore shipper, expects to add 28 million tonnes in 2017, representing about 58 percent of the global addition to seaborne supplies, the company said on Sept. 28.

    New supply from Australia, the top exporting nation, may be muted, with the major additions coming from the ongoing ramp up of the 56-million tonne a year Roy Hill mine in Western Australia state.

    Views within the industry are mixed, with Vale and number three Australian miner Fortescue Metals Group expecting the current stability in the market to continue, while second-ranked Australian producer BHP Billiton said in August that prices were still more biased to the downside.

    In some ways iron ore prices are currently trying to be like the baby bear's porridge, not too hot and not too cold.

    If they rise too much, it's likely Chinese domestic output that has been rendered uncompetitive will return to the market, but they also have to be wary of cooling by adding too much supply.

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